It has been proposed heretofore to use a noncondensible miscible gas such as carbon dioxide, nitrogen, methane and the like for stimulating oil production from a petroleum-bearing formation. Such gas is injected into at least one well and petroleum is produced from at least one other well, penetrating the same formation. In general these gases have a relatively low critical point, that is the temperature above which the gas cannot be compressed to a liquid. Such gases are at least partially soluble in the oil. Because these gases, although noncondensible, are in fact soluble, or miscible in the oil, they are absorbed by the petroleum, either to reduce the viscosity of the oil or to increase its mobility through the formation, and at the same time the increased pressure of the gas drives residual petroleum in the formation to a producing well or wells.
As with all enhanced oil-recovery processes, the formation is quite non-uniform having been formed initially as a geological bed and then entrapping oil and gas (generally by displacing water) and gas therein over geological time. Because of the heterogeneity of the formation, primarily due to the inclusion of clays or shale material in the sedimentary beds, permeability to flow of liquids through the formation is quite variable throughout its structure. Further, the permeability of the formation to flow of each of the components, oil, gas and water frequently differs substantially in various parts of the formation. In general, the formation permeability is substantially greater for gas than for oil or water. As a result, the injection gas tends to "finger" through the reservoir formation, and primarily due to density differences through upper portions of the reservoir. This creates gravity separation, known as "gravity override" of the gas so that it tends to by-pass, or break through, the reservoir between injection and producing wells. Additionally, water may also create preferential flow-paths and similarly by-pass oil in less permeable portions of the earth formation. It is of course, most desirable that the injected gas act on the fluids of the formation as a piston-like displacement so that all fluids move at substantially the same rate through the formation. Thus, desirably the "injection profile" for the gas is made as nearly equal as possible at all points in the reservoir.
It has been proposed heretofore to use foam in the same manner as it has been used in steam-assisted oil recovery methods to equalize the injection profile across the formation. The injected foam tends to block more gas permeable portions of the formation so that the steam or gas pressure is diverted toward oil in the less permeable channels of the formation. However, a particular problem encountered in most earth formations is that the connate water is relatively saline, that is, the water or brine has a relatively high salt content as compared to fresh water. Furthermore, the brine content varies substantially between geological provinces (such as California vs. Gulf Coast, or mid-continent fields) as well as from field to field and from formation to formation. Depending upon the geological formation, the environment in which the oil was originally generated, or captured within rocks serving as a reservoir, the salt content of the brine may vary from 1% or less by weight to water substantially saturated with salt, e.g., in excess of 12% by weight. Such variations in salt content of formation waters may be due to either the oil having been generated or trapped in substantially fresh water, such as littoral beds in lakes, seas or rivers that are relatively salt-free. Higher salt content of the brine may be found where the oil is captured in reefs including salt beds or along the edges of salt domes, where over geological ages the water became saturated by solution of the salt.
Because of such wide variations in the salt content, it has been found difficult both to form and maintain a foam which will remain stable in the presence of such brines. Further, the oil content of the formation may also prevent the formation of the foam or rapidly break such a foam when formed by a common foaming agent, such as alpha olefin sulfonates, in brine or water and introduced into a producing formation using a noncondensible miscible gas drive.
As particularly distinguished from prior art methods, the present invention forms a stable foam of the noncondensible, miscible gas, such as the gas being used in an enhanced oil recovery process in a reservoir and one or more alpha olefin sulfonates which are effective to form a foam that is stable in contact with reservoir fluids, including petroleum and water comparable in salt content to water present in the reservoir.